North Sea exploration: Risk appetite remains despite low oil prices

The North Sea has been a cash cow for the UK and Norway contributing to their economies for over half a century. However, to maintain regular activities in the near future, new commercial discoveries are necessary and to achieve this there needs to be a high level of exploration activity.

---

In addition to two major oil price crises that have shaken the industry since 2014, the energy transition wave is spreading, accelerated in some ways by the coronavirus pandemic.

The industry landscape is changing and the future is uncertain as ever but, for now, the North Sea exploration is still alive and kicking.

According to the UK’s Oil and Gas Authority (OGA), more than 44.7 billion barrels of oil equivalent (boe) have been produced from the UKCS and 10 to 20 billion boe are estimated to remain.

In order to realize the full potential of the remaining but seemingly depleting reserves from its sector of the North Sea, the UK has developed a strategy to maximise economic recovery (MER), which became a legal obligation on licensees in the UK in March 2016.

On the other side of the border, the Norwegian Petroleum Directorate has estimated the undiscovered resources on the Norwegian shelf at approximately 3.9 billion standard cubic metres of recoverable oil equivalents.

This corresponds to around 48 per cent of all the remaining resources on the shelf.

Undiscovered resources are split between the different sea areas with 18 per cent belonging to each the North Sea and the Norwegian Sea, and 64 per cent in the Barents Sea.

The Norwegian Petroleum Directorate’s estimate of total proven and unproven petroleum resources on the Norwegian continental shelf is about 15.7 billion standard cubic metres of oil equivalents.

Successful hydrocarbon discoveries lead to new field developments and additional output needed to offset the natural decline from existing fields, which is the key driver for North Sea exploration.

Despite the low levels of exploration activity in recent years, encouraging discoveries have recently been made in the West of Shetland and the Northern North Sea, Central North Sea, and Southern North Sea.

But before delving into what is ahead in the North Sea exploration, let’s have a look at exploration activity in the North Sea, the UK and Norwegian sector, over the last five years.

Following the oil price crash in 2014, the oil and gas industry saw a decline in exploration wells drilled both in the UK and Norway, which continued in the four years that followed.

In a webinar held recently by oil and gas market research provider, Westwood Energy, Dave Moseley, Westwood Senior Analyst NW Europe, said that between 2015 to 2019 there were 124 exploration wells drilled in the UK and Norway Central and Northern North Sea.

Out of those 124 wells, 79 were drilled in Norway and 45 in the UK. Around one billion barrels of oil equivalent was discovered in the North Sea between 2015 and 2019, replacing around 15 per cent of production.

Total exploration drilling spend of $5.2 billion gives a drilling finding cost of $4.85/boe, Moseley said.

Since 2015, there has been an overall decline in wells from 32 in 2015 to 14 wells in the North Sea in 2018.

The drilling activity hit a low in Norway in 2017 and in the UK in 2018.

In 2018, just four wells were completed in the UK sector, which was the lowest number since the 1960s.

The drilling activity in the North Sea recovered in 2019 driven by higher exploration budgets and a number of prospects, which were matured over the downturn.

At the beginning of 2020, Westwood expected exploration activity to be on par with last year’s with around 30 to 35 exploration wells.

Just as the E&P players were gearing up for more exploration drilling efforts, a new crisis hit the market in March 2020 with the oil price war between Russia and Saudi Arabia.

The rift between the two countries was caused by disagreements over oil production cuts due to falling demand exacerbated by the coronavirus pandemic.

As a result, there has been a big drop in activity levels in the first half of the year.

Following the outbreak of the coronavirus, E&P operators have moved quickly to slash their exploration budgets for this year and the next.

Final investment decisions for the projects have been postponed and drilling campaigns delayed or cancelled.

Oil majors like BP, Shell, Total, Equinor, Chevron, ConocoPhillips, and ExxonMobil were only some of the names to slash their exploration spending in the last few months to mitigate the effects of the coronavirus pandemic and the oil price crash.

In addition, expecting that the COVID-19 pandemic will have an enduring impact on the global economy, with potential for weaker demand for energy for a sustained period, BP in mid-June 2020 revised its long-term price assumptions and reviewed its intent to develop some of its exploration intangible assets.

These actions will lead to non-cash impairment charges and write-offs in the second quarter estimated to be in a range of $13 billion to $17.5 billion post-tax.

In light of the impact of COVID-19 and the ongoing challenging commodity price environment, Shell on 30 June revealed a revised long-term commodity price and margin outlook, which is expected to result in non-cash impairments in the range of $15 to $22 billion in the second quarter results.

Commenting on these actions in late June, Angus Rodger, a director with Wood Mackenzie’s upstream research team, said: “Cutting long-term price assumptions will generally result in a lower valuation for certain assets to below the accounting value held on the balance sheet. That’s what will trigger an impairment charge.

‘’This process has further to run, and we expect further large impairments to occur across the sector”.

Rodger added that the price crash and pandemic has already wiped $1.6 trillion off WoodMac’s valuation of the global upstream sector.

Luke Parker, Woodmac vice president, corporate analysis, said: “The impairment Shell has announced is about more than an accounting technicality, or an adjustment to near-term price assumptions. It’s about fundamental change hitting the entire oil and gas sector”.

Parker added: “Demand might still grow from here, and many companies are still chasing a share of that growth. But make no mistake, the corporate landscape is changing, and the majors are changing with it”.

Due to factors from early this year, much of the activity planned for 2020 has been deferred for 2021 and beyond.

Despite that, Westwood noted that, while activity levels were down, the performance was high.

Molesley said that eight wells were completed and four commercial discoveries were made in the North Sea during the first half of the year.

Out of those eight wells, six were in Norway and the remaining two in the UK. There are also four active wells in the North Sea, one in the UK and three in Norway.

When it comes to discoveries in the first half of 2020, Apache in early 2020 made a discovery with a Solar exploration well located in its Beryl area in the UK North Sea.

Furthermore, Total in March announced its hydrocarbons discovery in the Upper Jurassic and Triassic sandstone reservoirs of its Isabella exploration well in Block 30/12d in the UK Central North Sea.

The high-pressure high-temperature discovery is located about 40 kilometres south of the Elgin-Franklin field, which could potentially provide a tieback option for the development.

The well encountered 64 metres net pay, consisting of lean gas and condensate and high-quality light oil.

Over in Norway, Equinor in early March made its Sigrun East discovery as part of its infrastructure-led exploration efforts. The oil discovery is near the Gudrun in the central part of the North Sea.

Also in Norway, Hungarian operator MOL has made another North Sea discovery with the Iving/Evra well in the North Sea.

The oil and gas discoveries at the Evra and Iving exploration well are close to the Balder and Ringhorne field.

Another discovery, which was not announced at the time of Westwood’s webinar but is worth mentioning, is the one made by Neptune Energy just last week.

Namely, Neptune revealed last Friday that it had hit hydrocarbons at the Dugong well in the Norwegian sector of the North Sea.

The operations in the reservoir section are still at an early stage and final results are not yet available. A contingent side-track may be drilled to further define the extent of the discovery.

The Dugong is located 158 kilometres west of Florø, Norway, at a water depth of 330 metres, and is close to the existing production facilities of the Snorre field.

In terms of current activity, there is still a lot of infrastructure-led exploration drilling, targeting the traditional North Sea plays.

According to Westwood’s Moseley, very few companies have excelled in North Sea exploration in the last five years.

Success rates are mediocre, around one in four across the basin, and overall finding costs are high, Moseley said.

He also noted that being in the infrastructure is advantageous when exploring and that it should not be underestimated.

In terms of delivering the best performance, Moseley emphasized it is not just the case of the biggest discoveries or the most volumes, but actually creating value around the infrastructure, so value over volume, particularly in the North Sea, is the key.

“We saw an increase in high-impact drilling in the last five years and that appetite for risk is not expected to abate”, Moseley said.

The outlook is uncertain but plans show there are 46 exploration wells expected in the next 18 months and the infrastructure-led exploration continues to dominate.

The planned pool of wells for the next 18 months includes 12 high impact wells, suggesting risk appetite remains despite current low oil prices, Moseley concluded.

Header photo by SP Mac